Wells drilled through subsurface formations are used for, among other purposes, extracting useful fluids such as oil and gas. Some subsurface formations are treated (“stimulated”) by pumping fluid under pressure into such formations for the purpose of creating, propagating and propping open networks of fractures to enhance extraction of oil and gas. This technique is commonly known as “fracking”. It is known in the art to drill wells for fracking substantially along the geologic trajectory of certain subsurface formations, while drilling a plurality of such “directional” or “lateral” wells from proximate surface locations. U.S. Patent Application Publication No. 2011/0030963 filed by Demong et al. (“Demong”) discloses an exemplary arrangement of wells having proximate surface locations. Demong also describes controlled fluid pumping and valve equipment enabling selective opening of one or more wells to (1) fracking fluid delivery into selected wells or (2) flow from the subsurface formation to the surface.
Demong's background disclosure provides a useful general discussion of at least some aspects of the state of the current art. Demong's background is also applicable background to the technology described in this disclosure. The following background discussion includes adaptations of Demong's background disclosure where applicable to this disclosure.
During typical fracking operations, fluid is pumped into the formation at pressures that exceed the fracture pressure of the formations. The fractures in the formation thus opened up may be held open by pumping of material (proppant) that supports the fracture structurally after the fluid pressure on the formation is relieved. Other fluid treatments may include, for example, pumping acid into the wellbore to dissolve certain minerals present in the pore spaces of the formations that reduce the formation permeability.
Wellbores may be drilled into hydrocarbon-bearing formations along directed trajectories that may deviate from vertical. In land-based fracking deployments, such deviated wellbores may be drilled, for example, so that the surface locations of the wellbores are closely spaced on a relatively small land area called a “pad”, while the lowermost portions of the wellbore extend laterally from the respective surface locations in a selected drainage pattern. Such arrangement reduces or minimizes the amount of land surface affected by the fracking operations.
Conventionally, fracking operations on multiple wells drilled from a common surface pad typically require multiple connections and disconnections in order to (1) connect the pumping equipment hydraulically to one well, (2) pump the fluid, then (3) disconnect the pumping equipment from the well before another well can be fluid treated. Such conventional piping configurations often involve laying pipe from each fracking fluid delivery truck to a central collection manifold and then in single or multiple lines to the well being treated. The result is that a costly separate rig-up and rig down is required for every fracture treatment. Such operations can create, among other exposures, safety risks to personnel working on or near the pad or platform, and interference with the operation of wellbores that are producing oil and/or gas while the fluid treatment equipment is connected and disconnected from various wellbores on the pad or platform. Such connection and disconnection operations may also take considerable amounts of time to perform.
FIG. 1 illustrates “zipper fracking”, a conventional (prior art) approach to optimizing the multiple pipe connections described immediately above. On FIG. 1, pumping units 10 deliver fluid at pressure into manifold M1. Pumping units 10 may be conventional fracking pump and delivery trucks such as illustrated on FIG. 1. Manifold M1 may be known colloquially as a “missile” in some embodiments. Fluid transfer lines 20 on FIG. 1 deliver fluid from manifold M1 to manifold M2. Manifold M2 may be known colloquially as a “zipper frack” in some embodiments. Manifold M2 provides a plurality of control outputs 30. Control outputs 30 are each connected by one or more fluid delivery pipes to a “goat head” style manifold 40 atop a wellhead W. In oilfield fracking and well completion parlance, “goat head” refers to a style of manifold with a hollow body providing multiple fluid line connection points (e.g. flange faces).
Fluid delivery to wellheads W on FIG. 1 is controlled by actuation of control valves on control outputs 30. Advantageously, flow through each fluid delivery pipe connecting a control output 30 to a corresponding goat head 40 is independently controlled by a separate control valve. In this way, an operator may actuate different control valves at different times to deliver fluid from manifold M2 to selected wellheads W as desired.
The drawbacks of “zipper fracking” according to FIG. 1 include that the setup is very inefficient in use of hardware such as control outputs 30 and corresponding control valves. The setup of FIG. 1 calls for considerable hardware spending its time idle. Likewise, the labor required for setup and teardown is high, since each control output 30 requires multiple fluid delivery pipes to be physically connected and then disconnected from a goat head 40.
FIG. 2 illustrates another conventional (prior art) approach to delivering fracking fluid to a wellhead. Crane truck CT is positioned nearby a wellhead W into which fluid is desired to be delivered. Crane C on crane truck CT advantageously provides telescoping boom TB. As shown on FIG. 2, crane C and telescoping boom TB bring wellhead connector WC nearby wellhead W. A first operator, also nearby wellhead W, then manhandles wellhead connector WC onto wellhead W as wellhead connector WC hangs suspended from telescoping boom TB. Meanwhile, a second operator (not illustrated on FIG. 2) assists by making adjustments to the suspended position of wellhead connector WC via operation of crane C and telescoping boom TB.
Once the first operator has secured wellhead connector WC to wellhead W, piping P on crane truck CT may be connected to fracking fluid at operating pressures and delivery volumes. Fluid delivery to wellhead W may commence.
At the completion of fluid delivery, fluid flow through piping P is terminated, and the first operator may disconnect wellhead connector WC from wellhead W. The second operator then actuates crane C and telescoping boom TB to move wellhead connector WC towards a second wellhead W in range to be connected in the same manner as the first. Alternatively, the second operator moves wellhead connector WC onto crane truck CT with crane C. Crane truck CT may then be physically relocated to a position nearby a new wellhead W to be serviced.
There are several drawbacks to prior art fluid delivery according to FIG. 2. There are operator safety issues, particularly with the first operator required to manhandle wellhead connector WC onto wellhead W. The operation also optimally requires two operators. The operators must be skilled. Depending on local conditions and the skill level of the operators, manual connection of wellhead connector WC onto wellhead may be slow and imprecise. It is also likely that only a small number of wellheads W will be in range of crane truck CT without need for physically relocating crane truck CT.
There is therefore a need in the art for an improved fluid connection and delivery system for multiple wellheads that can reduce the amount of and complexity of conduit between fluid apparatus and selected wellheads in a multiple well system. Such an improved fluid delivery system will advantageously reduce risks to operating personnel safety. Embodiments of such an improved fluid delivery system will further optimize fluid delivery in high-pressure, high-volume fracking operations. Such optimizations will advantageously include automated and robotic control over spatial positioning of the fluid delivery system with respect to wellheads to be serviced.